PUBLIC DOCUMENTstmedia.startribune.com/documents/Crisp+unredacted... · 2014. 7. 2. · investigation into xcel energy’s monticello life cycle management/extended power uprate project

BEFORE THE MINNESOTA OFFICE OF ADMINISTRATIVE HEARINGS 600 North Robert Street

St. Paul, MN 55101

FOR THE MINNESOTA PUBLIC UTILITIES COMMISSION 121 7th Place East, Suite 350

St Paul MN 55101-2147 IN THE MATTER OF A COMMISSION INVESTIGATION INTO XCEL ENERGY’S MONTICELLO LIFE CYCLE MANAGEMENT/EXTENDED POWER UPRATE PROJECT AND REQUEST FOR RECOVERY OF COST OVERRUNS

MPUC Docket No. E002/CI-13-754 OAH Docket No. 48-2500-31139

DIRECT TESTIMONY AND ATTACHMENTS OF MARK W. CRISP, P.E.

ON BEHALF OF

THE DIVISON OF ENERGY RESOURCES OF THE MINNESOTA DEPARTMENT OF COMMERCE

JULY 2, 2014

PUBLIC DOCUMENT

DIRECT TESTIMONY OF MARK W. CRISP, P.E. IN THE MATTER OF A COMMISSION INVESTIGATION INTO XCEL ENERGY’S MONTICELLO LIFE CYCLE MANAGEMENT/EXTENDED POWER UPRATE PROJECT AND REQUEST FOR RECOVERY OF COST OVERRUNS MPUC DOCKET NO. E002/ CI-13-754 OAH DOCKET NO. 48-2500-31139 TABLE OF CONTENTS Section Page I. INTRODUCTION AND PURPOSE ...................................................................................... 1 II. BRIEF HISTORY OF MONTICELLO PLANT UPRATE PROJECT ........................................ 3 III. ANALYSIS OF XCEL’S PROJECT MANAGEMENT ............................................................ 5

A. Program Design and Scope Changes ................................................................... 9 B. Licensing Delays .................................................................................................. 11 C. Complexity of the Modification Installation ........................................................ 15

I. INTRODUCTION AND PURPOSE 1

Q. Please state your name, title and business address. 2

A. My name is Mark W. Crisp. I am the Managing Consultant of Global Energy & Water 3

Consulting, LLC. My business address is 4539 Woodvalley Drive, Suite 100, Acworth, 4

Georgia (Suburban Atlanta) 30101. 5

6

Q. Please provide your educational background and experience. 7

A. I graduated from the Georgia Institute of Technology (Ga. Tech) with a degree in Civil 8

Engineering. In addition to my studies in Civil Engineering, I also completed post 9

graduate studies in Finance and Accounting. Following completion of my formal 10

education, I was employed for seventeen (17) years by Arkansas Power & Light 11

(Middle South Utilities now Entergy – Arkansas) and Georgia Power 12

Company/Southern Company. During this time, I completed assignments in the 13

planning, siting, design, construction, and operations of nuclear, coal and 14

hydroelectric generating plants. In addition to my utility operating experience, I was 15

also responsible for technical due diligence on Southern Company’s International 16

Acquisition Team. In this capacity I was responsible for evaluating all operating, 17

environmental, staffing and operational aspects of power generating facilities, 18

worldwide, that were the focus of Southern Company’s acquisition strategy. 19

Following my employment in the utility industry, I became a consultant 20

providing services to electric, water, wastewater and natural gas utilities and 21

regulatory bodies throughout the continental U.S., Hawaii, Alaska and internationally. 22

I continue to provide these services as Managing Consultant 23

Crisp PUBLIC Direct / 1

at Global energy & Water Consulting, LLC. A list of major electric generating facilities 1

I have been involved with are set forth in DOC Ex. ___ MWC-1 (Crisp Direct). I am a 2

licensed professional engineer in Georgia, Florida and South Carolina. 3

My direct nuclear cost, schedule and construction experience has evolved 4

from my work at Arkansas Nuclear One 1 (ANO-1) in the early 1980’s while working 5

for Arkansas Power & light Company, then Middle South Utilities, now Entergy – 6

Arkansas on outage projects including the pipe hanger assembly review following the 7

Three Mile Island incident. I also provided construction support on Vogtle 1 & 2 as 8

an employee of Georgia Power Company and Southern Company Services, Inc. My 9

consulting also includes engagements as a consultant for El Paso Electric, a minority 10

owner of Palo Verde Nuclear Plant, reviewing the outage costs associated with the 11

steam generator replacement project and the rate impact to the minority owners. I 12

am also working with the Mississippi Public Service Commission Staff on pre-13

construction and licensing costs filed by Entergy- Mississippi for prudence review on 14

Grand Gulf 3, a new project proposed in Mississippi now on hold. 15

16

Q. Have you previously testified before the Minnesota Public Service Commission 17

(Commission)? 18

A. No. However, I have testified before the Arizona, Georgia, South Carolina, Maryland, 19

Mississippi and Utah Commissions. In addition, I have testified before the Federal 20

Energy Regulatory Commission (FERC), the Nuclear Regulatory Commission (NRC), 21

various committees of the United States Congress, and several Federal Courts in the 22

capacity of an expert witness. 23


Q. What is Global’s assignment in this proceeding? 1

A. Global’s assignment is to work with the Minnesota Department of Commerce 2

(Department or DOC) to investigate whether Xcel’s actions were prudent. We are to 3

evaluate, from an engineering perspective, whether Xcel’s decisions in response to 4

NRC directives, lessons learned from Fukushima, and any other relevant factors in 5

the time since the Commission issued a Certificate of Need (CN) for Monticello were 6

necessary and reasonable. Since the goal is to identify the causes and reasons for 7

the cost overruns that have occurred since the project was first approved, it is also 8

necessary to identify whether the level of costs that Xcel identified for various 9

components is reasonable. Finally, since the Extended Power Uprate (EPU) project 10

was conducted at the same time as the Life Cycle Management (LCM) project, it is 11

necessary to identify which cost increases are due to 1) solely the EPU, 2) solely the 12

LCM and 3) both projects. 13

14

Q. What is the purposes of your testimony in this proceeding? 15

A. The purpose of my testimony is to provide a technical review of Xcel’s Project 16

Management decisions and project management execution and how they impacted 17

costs throughout the project timeline from the point the Application for a CN was 18

made to the Commission throughout the execution of the LCM and EPU projects. 19

20

II. BRIEF HISTORY OF MONTICELLO PLANT UPRATE PROJECT 21

Q. Please describe Xcel’s application for Certificate of Need and its implications. 22

A. Xcel submitted to the Commission its application for a CN for an extended power 23

uprate to increase the generating capacity of the Monticello Plant on February 14, 24


2008. The Commission granted the Order for Certificate of Need and Accepting the 1

Environmental Assessment on January 8, 2009 (Docket No. E-002/CN-08-185). In 2

short, Xcel’s application proposed to increase the generating capacity of the 3

Monticello Nuclear Plant from 600 MW to an uprated capacity of 671 MW. 4

5

Q. Was this the first uprate project or Monticello Plant? 6

A. No. Monticello went through a similar uprate project in the late 1990’s beginning 7

with its request submitted to the NRC dated July 26, 1996. On September 16, 8

1998, the NRC granted Xcel (then Northern States Power Company) an Amendment 9

to its Facility Operating License (No 102) allowing Xcel to increase the maximum 10

reactor core thermal power level by 105 MWt, from 1670 MWt to 1775 MWt (6.3 11

percent increase). Monticello was able to increase its electric output from a nominal 12

rating of 550 MWe to a nominal value of 585 MWe.1 13

14

Q. How was Xcel able to accomplish its first uprate during the late 1990’s? 15

A. The original design of Monticello, as with any nuclear, coal or natural gas plant, 16

included additional operating margins with each component. It is normal to include 17

this additional margin in order to absorb some efficiency losses as equipment ages 18

over time. During the planning and design for the 1998 uprate project Xcel used 19

these margins in the existing equipment to uprate the electric output while making all 20

necessary modifications to meet NRC requirements for operational safety at the new 21

power output level. 22

1 One MW represents one million watts of energy, but does not specify the type of energy. For greater clarity, one MWe represents one million watts of electrical energy; by contrast, one MWt represents one million watts of thermal energy. In MW terms, the uprate approved in 1998 increased the capacity from 564 MW to 600 MW.


Xcel and General Electric (GE), the original plant designer, had to evaluate 1

exactly what the differential between the existing plant systems and the proposed 2

higher power output would require from those same plant systems while also making 3

certain that NRC requirements were met. This analysis and the subsequent uprate 4

produced a new “design basis” for the plant. The Company, in its application for 5

certificate of need discussed the original uprate project in 1998. The Company 6

articulated that: 7

This first power uprate at Monticello was completed by 8 making use of available excess equipment, system and 9 component capabilities at the site. The site was able to 10 increase generation by 35 MWe to a nominal net 11 electrical output to the grid of 585 MWe with very few 12 changes to installed plant equipment. 13

Cite: February 14, 2008 Petition to the Minnesota Public Utilities Commission for CN, 14 Docket No. E002/CN-08-185 at 3-14. 15

16

III. ANALYSIS OF XCEL’S PROJECT MANAGEMENT 17

Q. From a project management and project execution perspective, why is it important to 18

return to the original uprate project for discussion? 19

A. Xcel and GE, now GE Hitachi, would have produced an “as-built” summary of the 20

design modifications in the first uprate in order to meet NRC requirements and to 21

receive NRC approval. This as-built condition should have established the baseline, 22

or original starting point, for the conceptual design, implementation schedule, and 23

cost estimate for this power uprate project. The “as-built” condition would have or 24

should have also identified any excess component capability or expansion capability 25

of the existing plant components. The completion of the original uprate program in 26

1998 was able to take advantage of all available operating margins of electrical and 27

mechanical components of the plant. As a result, the latest life cycle management 28


and extended power uprate programs had to start from essentially a fresh start to 1

increase capacity further. 2

3

Q. Why was the fresh start for the 2nd EPU important for the project management? 4

A. As with every major project and most minor projects the overall execution of the 5

project is directly attributed to thorough and exhaustive project management. 6

Success is defined by the schedule, cost, and operational benefits the project is able 7

to accrue to the plant and to the ratepayers. Each attribute of overall project 8

management, including proper staffing, scope definition, scheduling, budgeting, 9

design, procurement, and construction is linked together to form a synergistic 10

approach to the overall execution of the project. A project cannot expect to be 11

completely successful if any one or more of the attributes fails to meet its goal. 12

Each of these attributes must be addressed as thoroughly as possible in the 13

initial project definition and the expectations defined for the schedule, scope, design, 14

construction, start-up, operation, and final cost. The project management for the 15

Monticello project suffered from failure of several of these activities to be adequately 16

defined and for responsibility to be assigned to fully able and skilled personnel at 17

each step in the process. 18

19

Q. Please explain in more detail your assessment of the project management 20

A. The project management function in any multidiscipline project requires extensive 21

and accurate pre-project definition. In the case of Monticello, a fully functioning and 22

operating nuclear plant, it is even more critical to establish the scope in great detail. 23


Failure to establish the scope at the outset all but guarantees schedule delays and 1

cost overruns. 2

3

Q. What kinds of issues need to be fully considered at the beginning of such a project? 4

A. Establishing the scope for the LCM/EPU project requires considerable coordination 5

among all of the involved departments of Xcel, internal management of Xcel, the 6

original designer of Monticello, the current responsible designer, in this case GE, and 7

all sub-designers supporting the original design and the scope of the LCM/EPU. 8

These entities need to accomplish the following tasks at the beginning of the project. 9

In an established and functioning plant the first step in developing the scope 10

of any project is to define the final outcome; that is, what is the project to 11

accomplish, how will the project be accomplished, and what is the scheduled 12

completion or operational date the project is to be completed. 13

Secondly, before any design is initiated, a fully integrated team representing 14

operations and designers must be assembled for the purpose of determining the 15

existing condition of plant equipment, whether the existing equipment has adequate 16

capacity to be used in the future plans or whether the existing equipment does not 17

have the remaining life or capacity to work within the new scheme. 18

At this point in the scoping process the goals of the project must be 19

specifically identified in order for the design team to begin the process of 20

establishing the requirements for new and replacement equipment. 21

In a parallel effort, the design team along with the plant operational team 22

must be physically evaluating the logistics required to dismantle any retired existing 23


equipment and remove those components from their specific installation sites within 1

the plant while determining the physical size and installation requirements of the 2

new equipment. Failing to follow these steps in the planning and design process 3

almost guarantees schedule delays and cost overruns during the actual process of 4

constructing the project. 5

6

Q. Did the issue of project management failures as you have described above occur 7

during the LCM/EPU project? 8

A. Yes, as acknowledged by the Company, initial scope definition and project planning 9

appeared to contribute significantly to the cost overruns of the Monticello LCM/EPU 10

project. The licensing process with the NRC was another area testified to by the 11

Company that caused cost overruns. However, as discussed in more detail by Dr. 12

William Jacobs and further explained later in this testimony, NRC delays did not 13

cause delays in the LCM/EPU project. 14

15

Q. What did the Company indicate about the inadequacy of their initial cost estimates? 16

A. Company Witness Mr. O’Connor expressed his understanding of the cost overruns in 17

his pre-filed testimony (Xcel Ex. ___ at 30 – 33, O’Connor Direct), identifying several 18

“overlapping” difficulties during the original scoping process that contributed to the 19

cost overruns. Mr. O’Connor testified that the “preliminary nature of our initial cost 20

estimates failed to capture the true costs necessary to implement the overall 21

design.” However, he further testified that “future requirements due to evolving 22

regulatory environment” was a major cause of the cost overruns. Furthermore he 23

specifically identified (i) Program design and scope changes; (ii) licensing delays; and 24


(iii) the complexity of the modification installation as the “major cost drivers.” (Xcel 1

Ex. ___ at 31, lines 10-15, O’Connor Direct) 2

3

Q. In general, how do you respond to these assertions? 4

A. While projects can experience unexpected circumstances, it was clear that Xcel did 5

not adequately follow the steps I outlined above regarding basic project planning and 6

management. Good project management works to avoid changes in program design 7

and scope by careful examination of the project as I describe above. Further, good 8

project management considers the complexity of modification installation early in the 9

process. As discussed further below, these factors had a significant effect on the 10

cost overruns; by contrast, our review does not support the assertion that licensing 11

delays were in fact an issue with the delay. 12

13

Q. Will you please discuss each of the three areas Mr. O’Connor attributes to the cost 14

overruns? 15

A. Yes. As noted above and as discussed below, the three areas are: 16

A. Program design and scope changes, 17

B. Licensing delays, and 18

C. Complexity of the modification installation. 19

20

A. PROGRAM DESIGN AND SCOPE CHANGES 21

Q. What did Mr. O’Connor say about changes in program design and scope? 22

A. Mr. O’Connor stated the following: 23


Our initial estimates were based on a high level 1 conceptual design for the Program. As we moved 2 through the early decisions on design, we chose to 3 undertake work that was central to the long-term viability 4 of the plant, and that enhanced the plant’s safety and 5 reliability. As required by NRC regulations and our 6 commitment to nuclear safety, we regularly reevaluate 7 the functionality and performance of the plant’s systems 8 and components. During the evaluations performed in 9 preparation for the Program we took care to identify all 10 components necessary to enable operations through life 11 extension so that we could implement those changes 12 during the 2009 and 2011 outages. These evaluations 13 resulted in new modifications and component 14 replacements being identified as necessary to complete 15 the LCM/EPU Program. 16

Xcel Ex. ___ at 31-32 (O’Connor Direct). 17

He also listed the four design changes as follows, noting that these costs 18

accounted for $406 million, or over 60 percent of the $665 million that Xcel 19

indicates is the total cost of the project: 20

(i) replacement of the feedwater heaters and associated 21 equipment; (ii) replacement of the reactor feed pumps 22 and motors; (iii) replacement of the entire condensate 23 demineralizer system; and (iv) upgrade of the 4 kV 24 electric distribution system to supplement the on-site 25 power capabilities of the plant. 26

Xcel Ex. ___ at 32 (O’Connor Direct). 27

28

Q. How do you respond? 29

A. Given the focus on my testimony on the reasonableness of Xcel’s management of the 30

project, I note that the program design and scope changes would have been 31

minimized with proper initial scoping of the project. That is the function of a well 32

thought-out scoping process. It may not have corrected all of the issues with scoping 33

but it certainly would have minimized the issues. 34


For example, Xcel should have anticipated the upgrade to the distribution 1

system at the plant early on in designing the system, rather than the ad-hoc 2

approach Xcel used. Xcel also should have known the size specifications of the new 3

equipment early in the process. Not having that basic information in the initial 4

estimates indicates that Xcel wasn’t thinking through the process adequately to 5

ensure that the design and scope were reasonably worked out at that time. 6

7

B. LICENSING DELAYS 8

Q. What did Mr. O’Connor state about licensing delays? 9

A. Mr. O’Connor attributed licensing delays as one the major cost drivers. Specifically, 10

he stated that “we expended substantially more dollars than we anticipated and 11

more time than any prior applicant to meet the increasingly rigorous NRC standards 12

and to provide new information in response to the NRC concerns.” Xcel Ex. ___ at 34 13

(O’Connor Direct). While his testimony indicated that the increase in licensing costs 14

went from $28.6 million to $60 million (increase of $31.4 million), he also stated 15

that “most importantly, the extended and unexpected licensing effort delayed our 16

ability to operate at uprate levels for the full duration of the extended license.” Xcel 17

Ex. ___ at 34-35 (O’Connor Direct). 18

19

Q. How do you respond? 20

A. As is evidenced by the NRC administrative record for the LCM license extension and 21

the EPU increase there were in reality minimal licensing delays attributable to the 22

NRC. The license renewal (LCM extension) process actually was completed in a very 23

expeditious manner. The application date to the NRC was March 24, 2005 and the 24


final decision and order was granted on November 8, 2006. The Extended Power 1

Uprate process was more lengthy but as discussed further below, not necessarily due 2

to NRC delays or added NRC requirements. 3

The EPU process was initiated November 5, 2008 with final notice provided by 4

the NRC on December 9, 2013, a 5-year process. The 5-year process included a 5

lengthy period amending the previous Facility Operating License and the revision to 6

Technical Specifications that included approximately sixty-three (63) official 7

correspondences between Xcel and the NRC. This is the time period when the 8

Fukushima incident occurred. I discuss below how this longer time period was 9

appropriate for safety reasons. 10

11

Q. What do you say about Mr. O’Connor’s statement that the delay meant that Xcel 12

could not use the uprate? 13

A. First, I note that I am not discussing the issue regarding whether the uprate will be in 14

place in 2014; my understanding is that this issue will be developed in Xcel’s current 15

rate case (Docket No. E002/GR-13-868). Second, I note that Xcel’s statement is 16

misleading in that it appears at face value to place considerable if not all the blame 17

on the NRC licensing process. NRC granted Xcel the License Renewal, which did not 18

include an EPU request, in November of 2006. The EPU application did not occur 19

until November of 2008. Had the EPU application only taken 2 years for approval, as 20

did the initial Xcel License Renewal, given Xcel’s construction period to install the 21

EPU, the operation of the plant at the 1671 MWe level could not have commenced 22

before 2013. Therefore, 5 years of the new extended license operating time frame 23

would still be lost. So it is misleading to make the assertion that the licensing effort 24


delayed the plant’s ability to operate at the uprate levels for any period within the 1

new license timeframe. 2

3

Q. Do you not see any issue regarding licensing that may have affected the costs of the 4

project? 5

A. Yes. The Company’s strategy leading from the License Renewal into the EPU 6

application is not only confusing but may have had some repercussions with regards 7

to schedules and timely issuance of the EPU approval. The NRC approved the 8

License Renewal in a timely manner on November 8, 2006. However, on March 31, 9

2008, the Company applied for a license amendment for an Extended Power Uprate 10

at Monticello, in which the Company made a statement that contradicted the 11

statements the Company made in the request for the license extension of the plant. 12

Specifically, in the Application for License Renewal in 2005 the Company 13

presented to the NRC, the Company stated: 14

Nuclear Management Company (“NMC” now Xcel) does 15 not propose to construct or alter any production or 16 utilization facility in connection with this renewal 17 application. The current licensing basis (“CLB”) will be 18 continued and maintained throughout the period of 19 extended operation. 20

DOC Ex. ___ at MWC-2 (Crisp Direct, Docket 50-263, License No.: DPR-22, Page1-11, 21 Section 1.3.5) 22

23 However, contrary to this commitment to the NRC, the Company initiated 24

studies and activities for the EPU as early as 2004 and it was 2 years from the date 25

the extended license was approved that the Company filed with the NRC a request 26

for a power uprate amendment. 27


On June 25, 2008, at the suggestion of the NRC, the Company withdrew its 1

Extended Power Uprate amendment request. The Company returned to the NRC on 2

November 5, 2008, and renewed its Extended Power Uprate amendment request. 3

The confusion, contradictory information to the NRC and start-stop process suggest 4

management indecisiveness and strategic planning that, at best, was not adequately 5

thought out. Further, these factors presented timing and schedule interruptions that 6

caused cost increases. 7

8

Q. Do you have other observations about the licensing delays? 9

A. Yes. I conclude that the licensing delays were not wholly the responsibility of the NRC 10

as Company Witness Mr. O’Connor suggests in his testimony at Page 34, Lines 2-15. 11

Moreover, part of the longer time period for the EPU was due to the NRC’s focus on 12

safety and public health, a goal that Xcel shares. For example, the Company was 13

required to perform extended analyses in order to meet various NRC requirements as 14

a result of the Company’s reasonable decision to use the NRC guidance regarding 15

the higher water temperatures in EPU’s (SECY-11-0014 CAP).2 Xcel’s Monticello EPU 16

application was the first to use this guidance. Without getting into the technical 17

details it is understandable that the schedule was delayed and costs impacted by the 18

2 NRC staff describe NRC guidance SECY-11-0014 CAP as follows: EPUs result in an increase in the temperature of the sump water (in pressurized-water reactors) and suppression pool water (in boiling-water reactors) during certain postulated accidents or abnormal events. This could affect the performance of the emergency core cooling system (ECCS) pumps taking suction from these water sources. In some cases, licensees have included containment accident pressure (CAP) in their safety analyses to demonstrate acceptable performance of the ECCS pumps. The [Advisory Committee on Reactor Safeguards] ACRS recommended changes to this practice in a letter to the Executive Director for Operations (EDO) dated March 18, 2009.

May 25, 2011 NRC memo of Eric J. Leeds to NRC Commissioners


approach the Company elected to use with the SECY -11-0014 CAP guidance. Thus, 1

if it was Xcel’s intention to do so, it is not fair or supportable to suggest that the 2

delays and costs were solely the responsibility of the NRC in its licensing process. 3

While neither Xcel nor the NRC could have anticipated that the Fukushima incident 4

would have occurred prior to that event, the Company’s election to use the SECY -11-5

0014 CAP guidance, which was new, resulted in a longer than normal approval 6

process. 7

Relating this issue to the Project Management issue, I conclude that Xcel’s 8

Licensing Team should have maintained extensive two-way communication with the 9

NRC as to the vulnerability of schedules using the chosen analysis path. The 10

Licensing Team should have been in constant contact with the NRC, particularly if a 11

new criterion or guidance was to be used in the license analysis phase. 12

13

C. COMPLEXITY OF THE MODIFICATION INSTALLATION 14

Q. What does the Company indicate about the complexity of installing the plant 15

modification? 16

A. The complexity of installing the plant the modification appears to be the single 17

largest impact to schedule and cost of the Project, as identified by Mr. O’Connor’s 18

Table 6. Specifically, Mr. O’Connor stated: 19

We incurred installation costs far in excess of our initial 20 installation estimate. Our installation costs were nearly 21 $290 million which is more than 40 percent of the total 22 spend. Our initial estimate of $320 million included only 23 $27.5 million for installation of the General Electric 24 portion of the wosrk. Our actual installation costs 25 explain the sizable majority of the costs in excess of our 26 initial $320 million estimate. 27

Xcel Ex. ___ at 35 (O’Connor Direct) 28


That is, Mr. O’Connor blames inadequate initial cost estimates for installation as 1

causing 40 percent of the cost overrun. The figures above indicate that Xcel 2

exceeded its original estimated installation cost of $27.5 million by 955 percent.3 3

4

Q. What are you observations about Xcel’s cost overruns for installation? 5

A. It is troubling that this area caused so much of the cost overrun since this is the area 6

where: 1) the Company and the Company’s contractors had the most control and 2) 7

advanced planning and information should have negated this area as a cause of cost 8

overruns. It is crucial for managers of any project to have a clear understanding of 9

the “complexity” issue whether it is in the licensing phase, design phase, material 10

manufacture phase, construction phase or start-up phase or any combination of 11

these areas. 12

It is also essential in a well-managed and executed Project Management Plan 13

that the initial design and the construction functions have a solid connection 14

between the two functions. A design can be fully functional “on paper.” However, 15

other issues may mean that the design cannot be physically built; these issues are 16

called controlling factors. In order to avoid such failures the Project Management 17

Team must require considerable time for the construction sub-Team to review and 18

sign-off on the design that it can actually be built as designed. 19

Further, the level of communications between the design sub-Team and the 20

construction sub-Team is much more important in a retrofit project, 21

3 Calculated as ($290 - $27.5)/$27.5*100 = 955.


such as the Monticello uprate, than in a new or “greenfield” site especially when the 1

project involves substantial increases in power as is the case with Monticello. The 2

design of “renewals and replacements” has controlling factors that a greenfield site 3

generally does not contend with during the design. 4

5

Q. What were some of the controlling factors for the Monticello updrate? 6

A. For Monticello, controlling factors included spacing, clearances, access, physical 7

arrangement, as well as existing capacity of certain equipment that would continue to 8

function in the uprated environment. These controlling factors clearly had material 9

effects on the costs of the project. Further, failure to recognize these conflicts is a 10

direct failure of Project Management. 11

12

Q. How could Xcel have recognized these controlling factors earlier in its planning for 13

this project? 14

A. This plant had been in operation for 40 years, with outages occurring roughly every 15

two years. During these outages, plant operating personnel were required to inspect 16

all sections of the plant. Obviously, Xcel was well aware of the physical arrangement 17

with the plant power block itself. Xcel and GE, the original designer of Monticello, 18

and the contractor hired by Xcel to perform initial scoping, design, and provide cost 19

estimating services knew or should have known about the physical arrangement 20

inside the power block. In addition, as acknowledged by Xcel, NRC regulations 21

require the Owner, Xcel, to maintain complete documentation as to design, design 22

modifications made 23


throughout the life of the project, and/or any changes in the Plant’s physical 1

arrangement that may have an impact on the design basis. Generally speaking this 2

is commonly referred to as the “as-built” condition. 3

Company Witness Mr. O’Connor’s testimony recognized this need for careful 4

design to some degree: 5

As required by the NRC regulations and our [Xcel’s] 6 commitment to nuclear safety, we [Xcel] regularly 7 reevaluate the functionality and performance of the 8 plant’s systems and components. During the 9 evaluations performed in preparation for the Program we 10 [Xcel] took care to identify all components necessary to 11 enable operations through life extension so that we 12 could implement those changes during the 2009 and 13 2011 outages. These evaluations resulted in new 14 modifications and component replacements being 15 identified as necessary to complete the LCM/EPU 16 Program. (Emphasis added). 17

Xcel Ex. ___ at 31-32 (O’Connor Direct) 18

19 Further, Mr. O’Connor goes into detail about Xcel’s initial evaluations and 20

further emphasizes that Xcel identified “all” components. He also explains the 21

impacts of Monticello’s 1960’s construction, in that the original design was 22

constructed on a “very small footprint” causing this LCM/EPU design to be “limited in 23

range of options and made aspects of installation more challenging. (Cite: O’Connor 24

Testimony at Page 33, Lines 1-3). 25

26

Q. How did the “very small footprint? Affect the complexity and cost of the project? 27

A. In simple terms, when the Plant was initially constructed, there were small “rooms” 28

that are like concrete vaults in the Plant that were built to contain the necessary 29

equipment inside the Plant. Gaining access to those “rooms” to 30


remove existing equipment and install new equipment is much more difficult and 1

costly than Xcel anticipated; however Xcel should have anticipated this difficulty and 2

cost. 3

For example, Xcel knew the dimensions of the containment “room” for the 4

feedwater heater. However, Xcel’s estimated cost of installing the new, much larger 5

feedwater heater did not take into account the significant difficulty in removing the 6

former feedwater heater, modifying the size of the then-existing concrete “room” and 7

installing the new, larger feedwater heater. In addition, Xcel was aware of the size of 8

the cable tray, where all cables were located, and should have been aware of the 9

significant difficulty that would be involved in installing the new cable equipment. 10

11

Q. How do you respond to Xcel’s arguments about the “very small footprint” being an 12

unexpected source of complexity for the project? 13

A. While there is no dispute that the age of the design and the small footprint affected 14

costs, it should not have been a critical issue causing cost overruns in the actual 15

design of LCM/EPU nor should these controlling factors have been a surprise to Xcel 16

or GE for construction; GE was the original designer and had access to all of this 17

information. It is simply unclear where the breakdown occurred that ultimately lead 18

to the cost increases and increased constructability costs; “complexity issues” should 19

not have been the cause of such high cost overruns of installation. 20

21

Q. What do you conclude from your observations? 22

A. Unfortunately, in my opinion, it does not appear that the level of skilled Project 23

Management, communications, and sufficient support for employees entrusted to 24


carry out the project was focused on this project until the later construction time 1

period when it became obvious to the Company that costs were spiraling far above 2

expectations. 3

4

Q. Please provide a short chronology of events leading up to the filing in this case that 5

you conclude had an impact on project management. 6

A. The project suffered from a number of “starts and stops,” changes in company 7

management, changes in design and construction team, and an overall disjointed 8

process. 9

• 2006 GE is engaged as the engineering, procurement and licensing team 10

responsible for the Monticello LCM/EPU project. 11

• 2007 Xcel chooses the Team of Day Zimmerman/Sargent Lundy instead of 12

GE to complete the project. 13

• 2010 Poor performance on the part of Day Zimmerman/Sargent Lundy led 14

to transfer of some project scope to Northern States Power (NSP), Xcel, and 15

then on to other contractors. 16

• 2011 Xcel retains Bechtel Corporation to take over and complete the 17

LCM/EPU project. 18

Each of these course corrections occurred at a time that significant cost 19

increases were experienced; however, as discussed further below, there were 20

additional cost increases not associated with a change in contractors. 21


Q. Why are the changes in contractors important to this project? 1

A. The loss of faith in a contractor due to continued design or construction problems, or 2

continued budget issues, or the failure to meet schedules are all very real 3

justification for removal of a contractor. However, there are serious ramifications 4

when a contractor is relieved of duty and a new contractor is brought on-board. It is 5

simply not a matter of “handing off” responsibilities to a new contractor. There are 6

serious risk management issues that must be addressed by not only the Company 7

but also the new contractor. This risk management takes on an even greater 8

significance when the design is not completed and the new contractor picks up 9

where the previous contractor left off, as was the case in this project. 10

Further, as Mr. O’Connor and Mr. Stall commented, the project design was 11

accomplished in parallel to the licensing activities and the construction activities. 12

The Engineer(s) and the Engineering Company cannot simply assume that previous 13

designs or designs in progress were performed to meet all codes and requirements 14

by all regulatory bodies that have jurisdiction. These personnel and firms must, by 15

requirement of their individual and Company professional licensure and liability 16

insurance, review, reanalyze, and reaffirm that any completed design or partial 17

design to be used in the project meets all professional and regulatory requirements. 18

Otherwise, the Company and the new contractor are at extreme risk of liability claims 19

throughout the life of the project and not just in the area where they have been 20

involved during the LCM/EPU project. This liability extends to other areas of the plant 21

that integrate with the LCM/EPU project as claims can be made that absent 22


the LCM/EPU there would not have been this exposure. With this expansion of risk 1

management exposure, the new contractor must mitigate this risk by spending 2

considerable time to reassess and analyze the position it faces as it takes over from 3

the previous contractor. Such changes and processes take considerable time, which 4

impacts the overall project schedule. 5

6

Q. When did these contractor changes happen with the Monticello project? 7

A. In the Monticello case, this occurred at least two significant times, in 2010 and 2011 8

as noted above. Therefore, considerable delays occurred as a result of these 9

contractor changes. These delays cost considerable dollars and could have been 10

mitigated with proper Company oversight and project management controls. 11

12

Q. Were there other changes that affected the cost overruns? 13

A. Yes. Xcel’s project management team suffered its own set of difficulties that 14

impacted the overall project schedule and budget. Mr. O’Connor reflects on the issue 15

of project management skills and effectiveness in his testimony: 16

As we moved through 2010, we began to face design 17 challenges and a need for greater oversight of quality 18 issues. We reacted well by quickly responding to 19 concerns, developing design solutions, establishing 20 recovery plans for the 2011 outage and eventually 21 changing the management structure following the 2011 22 outage. 23

24 Mr. O’Connor further stated that “the change was appropriate but it did not reduce 25

costs. In fact the 2013 outage experienced substantial[ly] longer up 26


front planning and design still took longer and cost more than we had forecast.” Xcel 1

Ex. ___ at 63 (O’Connor Direct). 2

Unfortunately, this result occurs in many projects that incur substantial 3

planning problems from the beginning due to lack of proper management controls 4

and an overly aggressive schedule, such as the expedited approach Xcel used with 5

Monticello, as discussed in Dr. Jacob’s testimony and as I discuss further below. 6

7

Q. When where the warning signs of the cost increases at Monticello first realized? 8

A. Based on Company documentation, it appears that as early as 2006, even before 9

Xcel submitted the CN with the Commission, there were severe signs of schedule and 10

budget impacts. At that time, the site project group recommended $89.5 million 11

more for the cost for the project, based on facts of which they were aware at that 12

time, than Xcel’s Board of Directors allowed: 13

The feasibility study was redone by GE [TRADE SECRET 14 DATA HAS BEEN EXCISED]. 15 Results were documented in GENE-0000-0050-16 8232, Extended Power Uprate Cost Scoping 17 Assessment, in May of 2006. Two schedules were 18 considered with one doing major modifications in 2009 19 and 2011 and the second showing major modifications 20 in 2011 and 2013. 21 22 Total cost was estimated as GE [TRADE SECRET DATA 23 HAS BEEN EXCISED] installed for those items required to 24 implement EPU. 25 26 Following consideration of the GE study, the site projects 27 group in July of 2006 recommended a budget of 28 $362.5M with final implementation in the 2013 RFO. 29 The higher cost was to recognize the uncertainty 30 associated with work scope and estimate quality. The 31 Xcel Board of Directors approved a $273M budget with a 32 2011 project completion in August of 2006. (Emphasis 33 added) 34

DOC Ex. ___ at MWC-3 (Crisp Trade Secret Direct) 35


Q. Please list the warning signs of cost increases that you observed. 1

A. During October of 2011, an internal status document was prepared at the request of the 2

then-Chief Nuclear Officer, Mr. Dennis Koehl, seeking “input on the Project structure and 3

opinions on the best way to proceed forward to complete the installation.” DOC Ex. ___ 4

at MWC-3 (Crisp Trade Secret Direct). This document details in chronological order the 5

issues that occurred. 6

The early cost estimate to implement the EPU was completed in 2004 by [TRADE 7

SECRET DATA HAS BEEN EXCISED] 8

and provided a “high” cost of [TRADE SECRET DATA HAS BEEN EXCISED]. 9

A revised estimate in 2006 10

estimated the project at TRADE SECRET DATA HAS BEEN EXCISED]. This estimate was 11

performed by the GE [TRADE SECRET DATA HAS BEEN EXCISED]. 12

The GE estimate was provided 13

to the Monticello Site Projects Group that, as noted above, recommended the budget be 14

expanded to $362.5 million due to uncertainty with work scope and estimate quality and 15

recommended the installation occur during the 2013 refueling outage (RFO). However, 16

without explanation, the Xcel Board disregarded the Monticello Site Projects Group, 17

approving a budget that was substantially (33 percent) lower than the amount 18

recommended by the “boots-on-the-ground” Team. Further, the Board of Directors 19

required the installation to occur in 2011, 2 years earlier than recommended by the 20

Monticello Site Projects Group, thus requiring a “fast track approach.” DOC Ex. ___ at 21

MWC-3 (Crisp Trade Secret Direct) 22

23

Q. What do you conclude from this information at the beginning of the project? 24


A. Regardless of the ultimate accuracy of the initial cost estimate provided by an 1

outside entity, the Monticello Site Projects Group, or the budget approved by the Xcel 2

Board, it is clear that there were significant issues with escalating costs and 3

scheduling issues as early as 2006. The discussion also points to a concern about 4

communication between the Board of Directors and the Monticello Site Projects 5

Group since the Monticello Site Projects Group’s recommendation was overruled by 6

the Board. 7

8

Q. Where there other signs of escalating budgets? 9

A. Yes. The escalating budget issues continued each year from 2006 through 2011, 10

the completion date of the EPU Cost History document prepared for Mr. Koehl. 11

Disregarding the actual cost increases in the instant discussion, the effect of a lack 12

of project controls on cost increases, “scope creep,” (expansion of scope) and 13

scheduling issues should have set off a significant warning to Xcel that Project 14

Management and Project Controls were severely lacking with regards to execution of 15

this project. 16

Thus, in the category where Xcel and its contractors had the most information 17

and the most control, the scope increase, budget increase in implementation and 18

schedule impacts should have been under better control. 19

20

Q. What were the specific problems caused by this inadequate control over the project? 21

A. Xcel’s internal document identified numerous Project Risks Related to Cost issues 22

that, as a whole, points to a dysfunctional Project Management program. Each one 23

of these points is significant; aggregating these issues presents a hurdle that is 24


nearly insurmountable unless there is proper management of a project of this size 1

and technical difficulty. 2

1) Initial Scope and Schedule Were Inadequate 3

a. As discussed above, in 2006 the Board approved a much lower budget for 4

the project than the site Project Team recommendation. 5

b. Also as discussed above, the Board approved a “fast track” approach 6

compared to the recommendation by the site Project Team. As stated in 7

Xcel’s internal document, this decision made all work activities ”fast track” 8

with “little ability to meet outage milestones.” Further, “There were 9

insufficient experienced, qualified personnel to manage workload of doing 10

two outages at once.” 11

c. Xcel’s internal document also indicated that “Engineering and construction 12

costs were poorly estimated and resulted in significant overruns and 13

delays. The ability to complete work in a timely fashion contributed to this 14

issue.” DOC Ex. ___ at MWC-3, page 3 (Crisp Trade Secret Direct) 15

2) Scope Control 16

a. Xcel’s internal document identified “The use of [TRADE SECRET DATA HAS 17

BEEN EXICSED] 18

defeated the ability to obtain detailed bids for each modification and 19

locked in modification scope suggested in the Cost Scoping Study.” 20

b. Xcel’s internal document also pointed out that “The EPU project team/site 21

comments on the GE purchase order were not incorporated into the 22

contract.” DOC Ex. ___ at MWC-3, page 3-4 (Crisp Trade Secret Direct) 23


These issues are all consistent with results that occur when a project has 1

project management issues. Xcel’s internal document goes on to establish 2

additional issues affecting budget and scope. These are listed below: 3

3) Lack of Site Ownership 4

a. Not using operational experiences recommended by the EPU Team 5

organization 6

b. Very limited capability for the project team to obtain a scope change 7

decision that balanced scope and cost. 8

c. The site did not have cost ownership of the budget. DOC Ex. ___ at MWC-9

3, page 4 (Crisp Trade Secret Direct) 10

4) Insufficient Project Controls 11

a. Changes to scope with an appropriate consideration of cost were 12

challenged by “fast track” schedule. 13

b. The expected cost impact was not reviewed by appropriate management 14

with requests to revisit past decisions to pursue added scope. 15

c. Project did not have separate cost tracking with many projects rolling up to 16

a single charge number. DOC Ex. ___ at MWC-3, pages 4-5 (Crisp Trade 17

Secret Direct) 18

Each and every one of these issues identified by Xcel’s internal document and 19

relayed to the then-Chief Nuclear Officer, Mr. Koehl, reflects that there was not a well-20

structured project management plan for this project. 21


Q. Please describe the impacts to the overall LCM/EPU cost due to the lack of quality 1

project management. 2

A. Due to Xcel’s methods of tracking costs, it is not possible to separate the costs 3

attributed to poor project management and execution from the costs associated with 4

the specific engineering design and construction costs without (at least) exhaustive 5

forensic accounting analysis. As was discussed in Xcel’s internal document (Section 6

4.c. Page 5 of 5) and confirmed by Mr. O’Connor in his testimony (Xcel Ex. ___ at 28, 7

Line 4, O’Connor Direct), the accounting of cost by categories and work orders was 8

not sufficiently detailed to accommodate a proper accounting reconciliation, certainly 9

not at the time of the expenditures. As a result, in this proceeding, Mr. Jacobs 10

identifies the levels of costs reasonably attributable to the LCM and EPU. 11

12

Q. Were project management issues a cause of cost overruns? 13

A. Yes, without a doubt, the inability to properly manage the scoping, the general 14

contractor, GE and its subcontractors, staffing issues and the various complexity 15

issues which should have been identified prior to any engineering design caused the 16

project to experience increased costs. 17

18

Q. Please explain how the scheduling issues impacted the schedule and budget. 19

A. “Fast track” refers to the project management effort requirement to engineer, 20

procure, and construct a project in an abnormally short period of time. In the 21

LCM/EPU project at Monticello, the schedule was to be completed in a single RFO 22

scheduled for 2011. 23


Unfortunately at the time this schedule was approved by the Xcel Board of Directors, 1

licensing had not begun, design was not started, little if any actual project definition 2

had been accomplished and certainly the overall Project Management Team was not 3

in a position to be responsible for such a project undertaking in this short of a 4

timeframe. An expedited project is successful in meeting schedule, budget and 5

constructability only if all components are completed ahead of the actual 6

implementation. 7

Projects such as Monticello with (as the Company indicates) a “small 8

footprint” benefit from the time and effort to build a 3-dimensional model on the 9

computer of the activities required to construct the design. Had Xcel not been so 10

aggressive with schedules a 3-D design model would have been invaluable to point 11

out conflicts and construction interferences. It is simply not wise to expedite a 12

project without the benefit of proper project planning on the front end. 13

Undoubtedly, the expedited approach caused delays and budget increases 14

that could have been avoided with proper pre-planning, project management and 15

proper design sequencing. Proper Project Management and management strategy 16

could have actually supported the 2011 or 2013 refueling outage. Unfortunately, 17

neither of these occurred satisfactorily. 18

19

Q. Please describe the issue of the lack of contingencies in the original budget and 20

throughout the various budget updates. 21

A. The use of contingencies in a design/construction budget is a method to recognize 22

the unknowns in the schedule and budgets. It is typical for preliminary budgets, 23

those budgets developed during the conceptual phase of a project, to include 24


significant budget contingencies due to all of the unknowns associated with a 1

conceptual design. At this time in a project planning process there is very little if any 2

actual design completed; certainly there has been no budgetary documentation 3

developed on the pricing of equipment or on the actual construction. The potential 4

for substantial cost variations at this point is very high. As the LCM/EPU project 5

moved through the process used by Xcel, the 30%/60%/90% method, the 6

contingencies could have been reduced due to the fact that more and more of the 7

project was becoming clear and well defined. 8

Unfortunately, Xcel, apparently chose not to use contingencies, or else did not 9

take the necessary time to identify the important, costly details of the project, for 10

some reason that is still unclear to me. 11

12

Q. Are you aware of any changes the Company may have made that would improve 13

project management? 14

A. I am aware that the Company has in-place at this time a document and a guiding 15

principle that could have prevented or minimized many, if not all, of the Project 16

Management issues that plagued the LCM/EPU project, had this policy been in-place 17

at the beginning of the LCM/EPU project and had the Company instilled the culture 18

described in the document. This document is the “Configuration Management” that 19

is Xcel Ex. ___ at TJO-1 Schedule 3 (O’Connor Direct). However, the document does 20

not have a date when it was published or when it was included in the Xcel Policy and 21

Procedures library, so it is not clear when the document was prepared. Further, the 22

document does not define or describe how the Principles and Behaviors were or are 23

to be communicated to Xcel employees and how Xcel intends to monitor the 24


establishment of this new culture. Therefore, without confirmation that this is the 1

newly embedded culture of Xcel it cannot be determined if LCM/EPU issues are in 2

the past. 3

4

Q. Mr. Crisp, are you aware that the NRC recently raised concerns with the degraded 5

performance at the Monticello Nuclear Plant? If so, what is your response? 6

A. I am generally aware of the management issue but have not studied the basis for the 7

NRC decision. My testimony focuses on the project management issues centered on 8

the cost overruns. It is my understanding that DOC witness, Ms. Campbell, 9

addresses this issue in her testimony. 10

11

Q. Does this conclude your testimony? 12

A. Yes. 13


NSP 0044603

PUBLIC DOCUMENT - TRADE SECRET DATA HAS BEEN EXCISED

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PROJECT RISK RELATED TO COST

1. INITIAL SCOPE AND SCHEDULE WERE INADEQUATEa.

SCOPE CONTROL

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Documents

PUBLIC DOCUMENTstmedia.startribune.com/documents/Crisp+unredacted... · 2014. 7. 2. · investigation into xcel energy’s monticello life cycle management/extended power uprate project